Electrically conductive proppant and methods for detecting, locating and characterizing the electrically conductive proppant

ABSTRACT

Electrically conductive proppants and methods for detecting, locating, and characterizing same are provided. The electrically conductive proppant can include a substantially uniform coating of an electrically conductive material having a thickness of at least 500 nm. The method can include injecting a hydraulic fluid into a wellbore extending into a subterranean formation at a rate and pressure sufficient to open a fracture therein, injecting into the fracture a fluid containing the electrically conductive proppant, electrically energizing the earth at or near the fracture, and measuring three dimensional (x, y, and z) components of electric and magnetic field responses at a surface of the earth or in an adjacent wellbore.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.14/593,447, filed Jan. 9, 2015, which is a continuation of U.S. patentapplication Ser. No. 14/147,372 filed Jan. 3, 2014, both of which areincorporated herein by reference in their entirety. U.S. patentapplication Ser. No. 14/593,447 is a continuation of InternationalPatent Application No. PCT/US2014/010228 filed Jan. 3, 2014, which isincorporated herein by reference in its entirety. U.S. patentapplication Ser. No. 14/147,372 and International Patent Application No.PCT/US2014/010228 each claim the benefit of U.S. Provisional PatentApplication No. 61/749,093 filed Jan. 4, 2013, which is incorporatedherein by reference in its entirety.

STATEMENT OF GOVERNMENTAL INTEREST

This invention was made under a CRADA (SC 11/01780.00) between CARBOCeramics, Inc. and Sandia National Laboratories, operated for the UnitedStates Department of Energy. The Government has certain rights in thisinvention.

BACKGROUND

Embodiments of the present invention relate generally to hydraulicfracturing of geological formations, and more particularly toelectromagnetic (EM) methods for detecting, locating, and characterizingelectrically conductive proppants used in the hydraulic fracturestimulation of gas, oil, or geothermal reservoirs. The methods describedherein involve electrically energizing the earth at or near a fractureat the depth of the fracture and measuring the electric and magneticfield responses at the earth's surface or in adjacent wells/boreholes.Other embodiments of the present invention relate to compositions andmethods for the formation of the electrically conductive proppants foruse in the electromagnetic methods for detecting, locating andcharacterizing such proppants.

In order to stimulate and more effectively produce hydrocarbons fromdownhole formations, especially formations with low porosity and/or lowpermeability, induced fracturing (called “frac operations”, “hydraulicfracturing”, or simply “fracing”) of the hydrocarbon-bearing formationshas been a commonly used technique. In a typical frac operation, fluidsare pumped downhole under high pressure, causing the formations tofracture around the borehole, creating high permeability conduits thatpromote the flow of the hydrocarbons into the borehole. These fracoperations can be conducted in horizontal and deviated, as well asvertical, boreholes, and in either intervals of uncased wells, or incased wells through perforations.

In cased boreholes in vertical wells, for example, the high pressurefluids exit the borehole via perforations through the casing andsurrounding cement, and cause the formations to fracture, usually inthin, generally vertical sheet-like fractures in the deeper formationsin which oil and gas are commonly found. These induced fracturesgenerally extend laterally a considerable distance out from the wellboreinto the surrounding formations, and extend vertically until thefracture reaches a formation that is not easily fractured above and/orbelow the desired frac interval. The directions of maximum and minimumhorizontal stress within the formation determine the azimuthalorientation of the induced fractures. Normally, if the fluid, sometimescalled slurry, pumped downhole does not contain solids that remainlodged in the fracture when the fluid pressure is relaxed, then thefracture re-closes, and most of the permeability conduit gain is lost.

These solids, called proppants, are generally composed of sand grains orceramic particles, and the fluid used to pump these solids downhole isusually designed to be sufficiently viscous such that the proppantparticles remain entrained in the fluid as it moves downhole and outinto the induced fractures. Prior to producing the fractured formations,materials called “breakers”, which are also pumped downhole in the fracfluid slurry, reduce the viscosity of the frac fluid after a desiredtime delay, enabling these fluids to be easily removed from thefractures during production, leaving the proppant particles in place inthe induced fractures to keep them from closing and therebysubstantially precluding production fluid flow there through.

The proppants may also be placed in the induced fractures with a lowviscosity fluid in fracturing operations referred to as “water fracs” or“slick water fracs”. The fracturing fluid in water fracs is water withlittle or no polymer or other additives. Water fracs are advantageousbecause of the lower cost of the fluid used. Also when usingcross-linked polymers, it is essential that the breakers be effective orthe fluid cannot be recovered from the fracture, effectively restrictingflow of formation fluids. Water fracs, because the fluid is notcross-linked, do not rely on the effectiveness of breakers.

Commonly used proppants include naturally occurring sands, resin coatedsands, and ceramic proppants. Ceramic proppants are typicallymanufactured from naturally occurring materials such as kaolin andbauxitic clays, and offer a number of advantages compared to sands orresin coated sands principally resulting from the compressive strengthof the manufactured ceramics and their highly spherical particle shape.

Although induced fracturing has been a highly effective tool in theproduction of hydrocarbon reservoirs, the amount of stimulation providedby this process depends to a large extent upon the ability to generatenew fractures, or to create or extend existing fractures, as well as theability to maintain connection to the fractures through appropriateplacement of the proppant. Without appropriate placement of theproppant, fractures generated during the hydraulic fracturing may tendto close, thereby diminishing the benefits of the hydraulic fracturingtreatment. However, reliable methods for detecting, locating andcharacterizing the placement of proppant within fractures at relativelyfar distances from the wellbore and thus confirming whether or not suchplacement has been appropriate are not available.

Current state of the art proppant identification techniques are limitedto relatively short distances (12 inches to 18 inches maximum) from thewellbore. Radioactive and non-radioactive tracers and proppants arecurrently used to infer the presence of proppant in the near well boreregion. A better understanding of proppant placement in the far fieldregions of a hydraulic fracture is needed.

Previous work for massive hydraulic fracture mapping is summarized inBartel, L. C., McCann, R. P., and Keck, L. J., Use of potentialgradients in massive hydraulic fracture mapping and characterization,prepared for the 51st Annual Fall Technical Conference and Exhibition ofSociety of Petroleum Engineers, New Orleans, Oct. 3-6, 1976 paper SPE6090. In this previous work, the electric potential differences weremeasured between two concentric circles of voltage electrodes around avertical fracture well at the earth's surface. The well was electricallyenergized at the top of the well casing or at the depth of the fracture.The electrical ground was established at a well located at a distance ofapproximately one mile from the fracture well. At that time, the factthat the grounding wire acted as a transmitting antenna was not takeninto account. The water used for the fracture process containedpotassium chloride (KCl) to enhance its electrical conductivity and thefracture was propped using non-conducting sand. A 1 Hz repetition ratesquare wave input current waveform was used and only the voltagedifference amplitudes were measured. Voltages using an elementary theorybased on current leakage from the well casing and the fracture into ahomogeneous earth were used to produce expected responses. Comparing thefield data to results from the elementary model showed that a fractureorientation could be inferred, however, since the model did not accountfor the details of the fracture, other fracture properties could not bedetermined using the elementary model.

A method of detecting, locating and characterizing the location of theproppant as placed in a hydraulic fracture at distances of more thanseveral inches from the cased wellbore is currently unavailable. Such amethod for detecting, locating and characterizing the proppant materialafter the proppant material is placed in a fracture would be beneficial.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention may best be understood by referring to the followingdescription and accompanying drawings that are used to illustrateembodiments of the invention. In the drawings:

FIG. 1 is a schematic illustration of a system for preparingsubstantially round and spherical particles from a slurry as describedherein.

FIG. 2 is a diagram of the geometric layout of a vertical or deviatedwell in which layers of the earth having varying electrical andmechanical properties are depicted.

FIG. 3 is a schematic of an installed horizontal wellbore casing stringtraversing a hydrocarbon bearing zone with proppant filled fractures inwhich layers of the earth having varying electrical and mechanicalproperties are depicted.

FIG. 4 is a schematic cross-sectional illustration of a hydraulicfracture mapping system which depicts two embodiments for introducingelectric current into a wellbore, namely energizing the wellbore at thesurface and energizing via a wireline with a sinker bar nearperforations in the wellbore.

FIG. 5 is a schematic plan illustration of a hydraulic fracture mappingsystem.

FIG. 6 is a schematic perspective illustration of a hydraulic fracturemapping system.

FIG. 7A is a schematic illustration of an electrically insulated casingjoint.

FIG. 7B is a schematic illustration of an electrically insulated casingcollar.

FIG. 8 is schematic illustration of a test system for measuring proppantelectrical resistance.

FIG. 9 is a graph of resistivity (Ohm-cm) vs. Closure Pressure (psi) forvarious proppant samples.

FIG. 10 is a graph of resistivity (Ohm-cm) vs. Closure Pressure (psi)for mixtures of CARBOLite 20/40 coated with aluminum and standardEconoProp 20/40 samples.

FIG. 11 is a graph of resistivity (Ohm-cm) vs. Closure Pressure (psi)for mixtures of Hydroprop 40/80 coated with aluminum and standardHydroprop 40/80 samples.

DETAILED DESCRIPTION

In the following description, numerous specific details are set forth.However, it is understood that embodiments of the invention may bepracticed without these specific details. In other instances, well-knownstructures and techniques have not been shown in detail in order not toobscure the understanding of this description.

Described herein are electromagnetic (EM) methods for detecting,locating, and characterizing electrically conductive proppants used inthe hydraulic fracture stimulation of gas, oil, or geothermalreservoirs. Also described herein are electrically conductive sintered,substantially round and spherical particles and methods for preparingsuch electrically conductive sintered, substantially round and sphericalparticles from a slurry of an alumina containing raw material for use asproppants in the electromagnetic methods. The term “substantially roundand spherical” and related forms, as used herein, is defined to mean anaverage ratio of minimum diameter to maximum diameter of about 0.8 orgreater, or having an average sphericity value of about 0.8 or greatercompared to a Krumbein and Sloss chart.

According to embodiments of the present invention, the electricallyconductive sintered, substantially round and spherical particles,referred to hereinafter as “electrically conductive proppant” may bemade from a conventional proppant such as a ceramic proppant, sand,plastic beads and glass beads. Such conventional proppants may bemanufactured according to any suitable process including, but notlimited to continuous spray atomization, spray fluidization, spraydrying, or compression. Suitable conventional proppants and methods fortheir manufacture are disclosed in U.S. Pat. No. 4,068,718 (whichrecites on Col 6 lines 24-28 “The data in Table I, however, clearlyshows that sintered bauxite particles having specific gravities between3.50 and about 3.80 (sample 4) possess ample compressive strength forhigh stress service.”), U.S. Pat. Nos. 4,427,068, 4,440,866, 5,188,175,and 7,036,591 (which recites in Column 5 lines 18-23 “Thus, thepreferred firing temperature range of from about 1200 to about 1350° C.is ideal for making a pellet that exhibits a very low apparent specificgravity and bulk density but maintains a percent crush at 4000 psi ofless than about 30%, preferably less than about 10%.”), the entiredisclosures of which are incorporated herein by reference.

Ceramic proppants vary in properties such as apparent specific gravityby virtue of the starting raw material and the manufacturing process.The term “apparent specific gravity” as used herein is the weight perunit volume (grams per cubic centimeter) of the particles, including theinternal porosity. Low density proppants generally have an apparentspecific gravity of less than 3.0 g/cm³ and are typically made fromkaolin clay and other alumina, oxide, or silicate ceramics. Intermediatedensity proppants generally have an apparent specific gravity of about3.1 to 3.4 g/cm³ and are typically made from bauxitic clay. Highstrength proppants are generally made from bauxitic clays with aluminaand have an apparent specific gravity above 3.4 g/cm³.

An electrically conductive material such as a metal, a conductivepolymer, or a conductive nanoparticle may be added in the manufacturingprocess of any one of these proppants to result in proppant suitable foruse according to certain embodiments of the present invention. Suitablemetals include aluminum, copper and nickel and can be added to result ina proppant having a metal content of from about 5% to about 10% byweight.

Suitable conductive polymers include poly(3,4-ethylenedioxythiophene)poly(styrenesulfonate) (PEDOT:PSS), polyanilines (PANI), andpolypyrroles (PPY) and can be added to result in a proppant having aconductive polymer content of from about 0.1% to about 10% by weight.Suitable PEDOT:PSS, PANI and PYY conductive polymers are commerciallyavailable from Sigma-Aldrich. Certain specific embodiments of processesfor coating proppant with a conductive polymer are described below inExample 2.

Suitable conducting nanoparticles include graphite, single ordouble-walled carbon nanotubes, or other material that when present inthe nanoscale particle size range exhibits sufficient electricalconductivity to allow for detection in the present invention. Suchconducting nanoparticles can be added to result in a proppant having aconducting nanoparticle content of from about 0.1% to about 10% byweight.

Ceramic proppant may also be manufactured in a manner that createsporosity in the proppant grain. A process to manufacture a suitableporous ceramic proppant is described in U.S. Pat. No. 7,036,591, theentire disclosure of which is incorporated herein by reference. In thiscase the electrically conductive material is impregnated into the poresof the proppant grains to a concentration of about 1% to 15% by weight.Water soluble coatings such as polylactic acid can be used to coat theseparticles to allow for delayed/timed release of conductingnano-particles for detection at different stages of the fracturetreatment.

According to certain embodiments of the present invention, theelectrically conductive material is coated onto the proppants. Thecoating may be accomplished by any coating technique well known to thoseof ordinary skill in the art such as spraying, sputtering, vacuumdeposition, dip coating, extrusion, calendaring, powder coating,transfer coating, air knife coating, roller coating and brush coating.

According to certain embodiments of the present invention, theelectrically conductive material is incorporated into a resin materialand ceramic proppant or natural sands are coated with the resin materialcontaining the electrically conductive material. Processes for resincoating proppants and natural sands are well known to those of ordinaryskill in the art. For example, a suitable solvent coating process isdescribed in U.S. Pat. No. 3,929,191, to Graham et al., the entiredisclosure of which is incorporated herein by reference. Anothersuitable process such as that described in U.S. Pat. No. 3,492,147 toYoung et al., the entire disclosure of which is incorporated herein byreference, involves the coating of a particulate substrate with aliquid, uncatalyzed resin composition characterized by its ability toextract a catalyst or curing agent from a non-aqueous solution. Also asuitable hot melt coating procedure for utilizing phenol-formaldehydenovolac resins is described in U.S. Pat. No. 4,585,064, to Graham et al,the entire disclosure of which is incorporated herein by reference.Those of ordinary skill in the art will be familiar with still othersuitable methods for resin coating proppants and natural sands.

As described herein, sintered, substantially round and sphericalparticles are prepared from a slurry of alumina-containing raw material.In certain embodiments, the particles have an alumina content of fromabout 40% to about 55% by weight. In certain other embodiments, thesintered, substantially round and spherical particles have an aluminacontent of from about 41.5% to about 49% by weight.

In certain embodiments, the sintered, substantially round and sphericalparticles have a bulk density of from about 1.35 g/cm³ to about 1.55g/cm³. The term “bulk density”, as used herein, refers to the weight perunit volume, including in the volume considered, the void spaces betweenthe particles. In certain other embodiments, the particles have a bulkdensity of from about 1.40 g/cm³ to about 1.50 g/cm³.

In certain embodiments, the sintered, substantially round and sphericalparticles have a crush strength at 10,000 psi of from about 5% to about8.5%, and a long term fluid conductivity at 10,000 psi of from about2500 mD-ft to about 3000 mD-ft. In certain other embodiments, thesintered, substantially round and spherical particles have a crushstrength at 10,000 psi of from about 5% to about 7.5%.

In still other embodiments, the sintered, substantially round andspherical particles have an apparent specific gravity of from about 2.50to about 3.00. The term “apparent specific gravity,” (ASG) as usedherein, refers to a number without units that is defined to benumerically equal to the weight in grams per cubic centimeter of volume,including void space or open porosity in determining the volume.

According to other embodiments, the sintered, substantially round andspherical particles have a size of from about 20 to about 40 U.S. Mesh.

According to certain embodiments described herein, the sintered,substantially round and spherical particles are made in a continuousprocess, while in other embodiments, the particles are made in a batchprocess.

Referring now to FIG. 1, an exemplary system for implementing acontinuous process for preparing sintered, substantially round andspherical particles from a slurry is illustrated. The exemplary systemillustrated in FIG. 1 is similar in configuration and operation to thatdescribed in U.S. Pat. No. 4,440,866, the entire disclosure of which isincorporated herein by reference. The operations performed by theexemplary system illustrated in FIG. 1 can also be used to make theparticles according to a batch process, as described in Example 1 below.

In the system illustrated in FIG. 1, an alumina-containing raw materialhaving an alumina content of from about 40% to about 55% by weight (on acalcined basis) is passed through a shredder 105 which slices and breaksapart the raw material into small chunks. In some embodiments, when theraw material as mined, or as received, (referred to herein as“untreated” raw material) is of such consistency that it can beprocessed as described herein without shredding, the shredder may bebypassed. Raw material fed through a shredder such as is illustrated inFIG. 1, is referred to as “treated” raw material.

In certain embodiments, the shredder breaks apart and slices thealumina-containing raw material so as to yield pieces having a diameterof less than about five inches, although pieces having smaller andlarger diameters can be further processed into a slurry as describedherein. Shredders and numerous other devices for slicing, chopping orcomminuting the alumina-containing raw material, as well as commercialsources for same, such as the Gleason Foundry Company, are well known tothose of ordinary skill in the art.

The treated or untreated alumina-containing raw material and water arefed to a blunger 110, which has a rotating blade that imparts a shearforce to and further reduces the particle size of the raw material toform a slurry. In a continuous process, the raw material and water arecontinuously fed to the blunger. Blungers and similar devices for makingslurries of such materials, as well as commercial sources for same arewell known to those of ordinary skill in the art.

In certain embodiments, the electrically conductive material is added tothe alumina-containing raw material and water in the blunger 110 toresult in an electrically conductive material concentration of about 5%to about 10% by weight of the solids content in the slurry or just priorto the formation of pellets as described below.

A sufficient amount of water is added to the blunger 110 to result in aslurry having a solids content in the range of from about 40% to about60% by weight. In certain embodiments, a sufficient amount of water isadded to the slurry such that the solids content of the slurry is fromabout 45% to about 55% by weight. In still other embodiments, asufficient amount of water is added to the slurry such that the solidscontent of the slurry is about 50% by weight. The water added to theblunger 110 can be fresh water or deionized water. In a continuousprocess for preparing the slurry, the solids content of the slurry isperiodically analyzed and the amount of water fed to the slurry adjustedto maintain the desired solids content. Methods for analyzing the solidscontent of a slurry and adjusting a feed of water are well known andunderstood by those of ordinary skill in the art.

In certain embodiments, a dispersant is added to the slurry in theblunger 110 to adjust the viscosity of the slurry to a target range asdiscussed further below. In other embodiments, the viscosity of theslurry in the blunger 110 is adjusted to the target range by theaddition of a dispersant and a pH-adjusting reagent.

A dispersant may be added to the slurry prior to the addition of theelectrically conductive material or other additives. In certainembodiments, the composition includes a dispersant in an amount of fromabout 0.15% to about 0.30% by weight based on the dry weight of thealumina-containing raw material.

Exemplary materials suitable for use as a dispersant in the compositionsand methods described herein include but are not limited to sodiumpolyacrylate, ammonium polyacrylate, ammonium polymethacrylate, tetrasodium pyrophosphate, tetra potassium pyrophosphate, polyphosphate,ammonium polyphosphate, ammonium citrate, ferric ammonium citrate, andpolyelectrolytes such as a composition of ammonium polymethacrylate andwater commercially available from a variety of sources, such as, KemiraChemicals under the trade name C-211, Phoenix Chemicals, Bulk ChemicalSystems under the trade name BCS 4020 and R.T. Vanderbilt Company, Inc.under the trade name DARVAN C. Generally, the dispersant can be anymaterial that will adjust the viscosity of the slurry to a targetviscosity such that the slurry can be subsequently processed through oneor more pressure nozzles of a fluidizer. In certain embodiments, thetarget viscosity is less than 150 centipoises (cps) (as determined on aBrookfield Viscometer with a #61 spindle). In other embodiments, thetarget viscosity is less than 100 cps.

According to embodiments in which a pH-adjusting reagent is used, asufficient amount of a pH-adjusting reagent is added to the slurry toadjust the pH of the slurry to a range of from about 8 to about 11. Incertain embodiments, a sufficient amount of the pH-adjusting reagent isadded to the slurry to adjust the pH to about 9, about 9.5, about 10 orabout 10.5. The pH of the slurry can be periodically analyzed by a pHmeter, and the amount of pH-adjusting reagent fed to the slurry adjustedto maintain a desired pH. Methods for analyzing the pH of a slurry andadjusting the feed of the pH-adjusting reagent are within the ability ofthose of ordinary skill in the art. Exemplary materials suitable for useas a pH-adjusting reagent in the compositions and methods describedherein include but are not limited to ammonia and sodium carbonate.

Generally, the target viscosity of the compositions is a viscosity thatcan be processed through a given type and size of pressure nozzle in afluidizer, without becoming clogged. Generally, the lower the viscosityof the slurry, the more easily it can be processed through a givenfluidizer. However, the addition of too much dispersant can cause theviscosity of the slurry to increase to a point that it cannot besatisfactorily processed through a given fluidizer. One of ordinaryskill in the art can determine the target viscosity for given fluidizertypes through routine experimentation.

The blunger 110 mixes the alumina-containing raw material, electricallyconductive material, water, dispersant and pH-adjusting reagent until aslurry is formed. The length of time required to form a slurry isdependent on factors such as the size of the blunger, the speed at whichthe blunger is operating, and the amount of material in the blunger.

From the blunger 110, the slurry is fed to a tank 115, where the slurryis continuously stirred, and a binder is added in an amount of fromabout 0.2% to about 5.0% by weight, based on the total dry weight of thealumina-containing raw material and the electrically conductivematerial. In certain embodiments, the binder is added in an amount offrom about 0.2% to about 3.0% by weight based on the total dry weight ofthe alumina-containing raw material and the electrically conductivematerial. Suitable binders include but are not limited to polyvinylacetate, polyvinyl alcohol (PVA), methylcellulose, dextrin and molasses.In certain embodiments, the binder is PVA having a molecular weight offrom about 20,000 to 100,000 Mn. “Mn” represents the number averagemolecular weight which is the total weight of the polymeric molecules ina sample, divided by the total number of polymeric molecules in thatsample.

The tank 115 maintains the slurry created by the blunger 110. However,the tank 115 stirs the slurry with less agitation than the blunger, soas to mix the binder with the slurry without causing excessive foamingof the slurry or increasing the viscosity of the slurry to an extentthat would prevent the slurry from being fed through the pressurizednozzles of a fluidizer.

In another embodiment, the binder can be added to the slurry while inthe blunger. In this embodiment, the blunger optionally has variablespeeds, including a high speed to achieve the high intensity mixing forbreaking down the raw material into a slurry form, and a low speed tomix the binder with the slurry without causing the above-mentionedexcessive foaming or increase in viscosity.

Referring again to the tank 115 illustrated in FIG. 1, the slurry isstirred in the tank, after addition of the binder, for a time sufficientto thoroughly mix the binder with the slurry. In certain embodiments,the slurry is stirred in the tank for up to about 30 minutes followingthe addition of binder. In other embodiments, the slurry is stirred inthe tank 115 for at least about 30 minutes. In still other embodiments,the slurry is stirred in the tank for more than about 30 minutes afteraddition of the binder.

Tank 115 can also be a tank system comprised of one, two, three or moretanks. Any configuration or number of tanks that enables the thoroughmixing of the binder with the slurry is sufficient. In a continuousprocess, water, and one or more of dust, oversize particles, orundersize particles from a subsequent fluidizer or other apparatus canbe added to the slurry in the tank 115.

From the tank 115, the slurry is fed to a heat exchanger 120, whichheats the slurry to a temperature of from about 25° C. to about 90° C.From the heat exchanger 120, the slurry is fed to a pump system 125,which feeds the slurry, under pressure, to a fluidizer 130.

A grinding mill(s) and/or a screening system(s) (not illustrated) can beinserted at one or more places in the system illustrated in FIG. 1 priorto feeding the slurry to the fluidizer to assist in breaking anylarger-sized alumina-containing raw material down to a target sizesuitable for feeding to the fluidizer. In certain embodiments, thetarget size is less than 230 mesh. In other embodiments, the target sizeis less than 325 mesh, less than 270 mesh, less than 200 mesh or lessthan 170 mesh. The target size is influenced by the ability of the typeand/or size of the pressure nozzle in the subsequent fluidizer toatomize the slurry without becoming clogged.

If a grinding system is employed, it is charged with a grinding mediasuitable to assist in breaking the raw material down to a target sizesuitable for subsequent feeding through one or more pressure nozzles ofa fluidizer. If a screening system is employed, the screening system isdesigned to remove particles larger than the target size from theslurry. For example, the screening system can include one or morescreens, which are selected and positioned so as to screen the slurry toparticles that are smaller than the target size.

Referring again to FIG. 1, fluidizer 130 is of conventional design, suchas described in, for example, U.S. Pat. No. 3,533,829 and U.K. PatentNo. 1,401,303. Fluidizer 130 includes at least one atomizing nozzle 132(three atomizing nozzles 132 being shown in FIG. 1), which is a pressurenozzle of conventional design. In other embodiments, one or moretwo-fluid nozzles are suitable. The design of such nozzles is wellknown, for example from K. Masters: “Spray Drying Handbook”, John Wileyand Sons, New York (1979).

Fluidizer 130 further includes a particle bed 134, which is supported bya plate 136, such as a perforated, straight or directional plate. Hotair flows through the plate 136. The particle bed 134 comprises seedsfrom which green pellets of a target size can be grown. The term “greenpellets” and related forms, as used herein, refers to substantiallyround and spherical particles which have been formed from the slurry butare not sintered. When a perforated or straight plate is used, the seedsalso serve to obtain plug flow in the fluidizer. Plug flow is a termknown to those of ordinary skill in the art, and can generally bedescribed as a flow pattern where very little back mixing occurs. Theseed particles are smaller than the target size for green pellets madeaccording to the present methods. In certain embodiments, the seedcomprises from about 5% to about 20% of the total volume of a greenpellet formed therefrom. Slurry is sprayed, under pressure, through theatomizing nozzles 132, and the slurry spray coats the seeds to formgreen pellets that are substantially round and spherical.

External seeds can be placed on the perforated plate 136 beforeatomization of the slurry by the fluidizer begins. If external seeds areused, the seeds can be prepared in a slurry process similar to thatillustrated in FIG. 1, where the seeds are simply taken from thefluidizer at a target seed size. External seeds can also be prepared ina high intensity mixing process such as that described in U.S. Pat. No.4,879,181, the entire disclosure of which is hereby incorporated byreference.

According to certain embodiments, external seeds are made from either araw material having at least the same alumina content as the rawmaterial used to make the slurry, or from a raw material having more orless alumina than the raw material used to make the slurry. In certainembodiments, the slurry has an alumina content that is at least 10%, atleast 20%, or at least 30% less than that of the seeds. In otherembodiments, the external seeds have an alumina content less than thatof the slurry, such as at least 10%, at least 20%, or at least 30% lessthan that of the slurry.

Alternatively, seeds for the particle bed are formed by the atomizationof the slurry, thereby providing a method by which the slurry“self-germinates” with its own seed. According to one such embodiment,the slurry is fed through the fluidizer 130 in the absence of a seededparticle bed 134. The slurry droplets exiting the nozzles 132 solidify,but are small enough initially that they get carried out of thefluidizer 130 by air flow and caught as “dust” (fine particles) by adust collector 145, which may, for instance, be an electrostaticprecipitator, a cyclone, a bag filter, a wet scrubber or a combinationthereof. The dust from the dust collector is then fed to the particlebed 134 through dust inlet 162, where it is sprayed with slurry exitingthe nozzles 132. The dust may be recycled a sufficient number of times,until it has grown to a point where it is too large to be carried out bythe air flow and can serve as seed. The dust can also be recycled toanother operation in the process, for example, the tank 115.

Referring again to FIG. 1, hot air is introduced to the fluidizer 130 bymeans of a fan and an air heater, which are schematically represented at138. The velocity of the hot air passing through the particle bed 134 isfrom about 0.9 meters/second to about 1.5 meters/second, and the depthof the particle bed 134 is from about 2 centimeters to about 60centimeters. The temperature of the hot air when introduced to thefluidizer 130 is from about 250° C. to about 650° C. The temperature ofthe hot air as it exits from the fluidizer 130 is less than about 250°C., and in some embodiments is less than about 100° C.

The distance between the atomizing nozzles 132 and the plate 136 isoptimized to avoid the formation of dust which occurs when the nozzles132 are too far away from the plate 126 and the formation of irregular,coarse particles which occurs when the nozzles 132 are too close to theplate 136. The position of the nozzles 132 with respect to the plate 136is adjusted on the basis of an analysis of powder sampled from thefluidizer 130.

The green pellets formed by the fluidizer accumulate in the particle bed134. In a continuous process, the green pellets formed by the fluidizer130 are withdrawn through an outlet 140 in response to the level ofproduct in the particle bed 134 in the fluidizer 130, so as to maintaina given depth in the particle bed. A rotary valve 150 conducts greenpellets withdrawn from the fluidizer 130 to an elevator 155, which feedsthe green pellets to a screening system 160, where the green pellets areseparated into one or more fractions, for example, an oversize fraction,a product fraction, and an undersize fraction.

The oversize fraction exiting the screening unit 160 includes thosegreen pellets that are larger than the desired product size. In acontinuous process, the oversize green pellets may be recycled to tank115, where at least some of the oversize green pellets can be brokendown and blended with slurry in the tank. Alternatively, oversize greenpellets can be broken down and recycled to the particle bed 134 in thefluidizer 130. The undersize fraction exiting the screening system 160includes those green pellets that are smaller than the desired productsize. In a continuous process, these green pellets may be recycled tothe fluidizer 130, where they can be fed through an inlet 162 as seedsor as a secondary feed to the fluidizer 130.

The product fraction exiting the screening system 160 includes thosegreen pellets having the desired product size. These green pellets aresent to a pre-sintering device 165, for example, a calciner, where thegreen pellets are dried or calcined prior to sintering. In certainembodiments, the green pellets are dried to a moisture content of lessthan about 18% by weight, or less than about 15% by weight, about 12% byweight, about 10% by weight, about 5% by weight, or about 1% by weight.

After drying and/or calcining, the green pellets are fed to a sinteringdevice 170, in which the green pellets are sintered for a period of timesufficient to enable recovery of sintered, substantially round andspherical particles having one or more of a desired apparent specificgravity, bulk density, and crush strength. Alternatively, thepre-sintering device 165 can eliminated if the sintering device 170 canprovide sufficient calcining and/or drying conditions (i.e., dryingtimes and temperatures that dry the green pellets to a target moisturecontent prior to sintering), followed by sufficient sinteringconditions.

The specific time and temperature to be employed for sintering isdependent on the starting ingredients and the desired density for thesintered particles. In some embodiments, sintering device 170 is arotary kiln, operating at a temperature of from about 1000° C. to about1600° C., for a period of time from about 5 to about 90 minutes. Incertain embodiments, a rotary kiln is operated at a temperature of about1000° C., about 1200° C., about 1300° C., about 1400° C. or about 1500°C. In certain embodiments, the green pellets have a residence time inthe sintering device of from about 50 minutes to about 70 minutes, orfrom about 30 minutes to about 45 minutes. After the particles exit thesintering device 170, they can be further screened for size, and testedfor quality control purposes. Inert atmosphere sintering can be used tolimit or prevent the oxidation of the electrically conductive material.Techniques for replacing the oxygen rich atmosphere in the sinteringdevice with an inert gas such as argon, nitrogen, or helium are wellknown to those of ordinary skill in the art. Generally, oxygen isreplaced with an inert gas such that 0.005% oxygen or less remains inthe sintering atmosphere.

The electromagnetic methods described herein involve electricallyenergizing the earth at or near a fracture at depth and measuring theelectric and magnetic responses at the earth's surface or in adjacentwells/boreholes. The electromagnetic methods described herein aretypically used in connection with a cased wellbore, such as well 20shown in FIG. 2. Specifically, casing 22 extends within well 20 and well20 extends through geological strata 24 a-24 i in a manner that hasthree dimensional components.

Referring now to FIG. 3, a partial cutaway view is shown with productionwell 20 extending vertically downward through one or more geologicallayers 24 a-24 i and horizontally in layer 24 i. While wells areconventionally vertical, the electromagnetic methods described hereinare not limited to use with vertical wells. Thus, the terms “vertical”and “horizontal” are used in a general sense in their reference to wellsof various orientations.

The preparation of production well 20 for hydraulic fracturing typicallycomprises drilling a bore 26 to a desired depth and then in some casesextending the bore 26 horizontally so that the bore 26 has any desireddegree of vertical and horizontal components. Casing 22 is cemented 28into well 20 to seal the bore 26 from the geological layers 24 a-24 i inFIG. 3. The casing 22 has a plurality of perforations 30. Theperforations 30 are shown in FIG. 3 as being located in a horizontalportion of well 20 but those of ordinary skill in the art will recognizethat the perforations can be located at any desired depth or horizontaldistance along the bore 26, but are typically at the location of ahydrocarbon bearing zone in the geological layers 24, which may bewithin one or more of the geological layers 24 a-24 j. The hydrocarbonbearing zone may contain oil and/or gas, as well as other fluids andmaterials that have fluid-like properties. The hydrocarbon bearing zonein geological layers 24 a-24 j is hydraulically fractured by pumping afluid into casing 22 and through perforations 30 at sufficient rates andpressures to create fractures 32 and then incorporating into the fluidan electrically conducting proppant which will prop open the createdfractures 32 when the hydraulic pressure used to create the fractures 32is released.

The hydraulic fractures 32 shown in FIG. 3 are oriented radially awayfrom the metallic well casing 22. This orientation is exemplary innature. In practice, hydraulically-induced fractures 32 may be orientedradially as in FIG. 3, laterally or intermediate between the two.Various orientations are exemplary and not intended to restrict or limitthe electromagnetic methods described herein in any way.

According to certain embodiments of the electromagnetic method of thepresent invention and as shown schematically in FIG. 4, electric currentis carried down wellbore 20 to an energizing point which will generallybe located within 10 meters or more (above or below) of perforations 30in casing 22 via a seven strand wire line insulated cable 34, such asthose which are well known to those of ordinary skill in the art and arewidely commercially available from Camesa Wire, Rochester Wire andCable, Inc., WireLine Works, Novametal Group, and Quality Wireline &Cable Inc. A sinker bar 36 connected to the wire line cable 34 contactsor is in close proximity to the well casing 22 whereupon the well casing22 becomes a current line source that produces subsurface electric andmagnetic fields. These fields interact with the fracture 32 containingelectrically conducting proppant to produce secondary electric andmagnetic fields that will be used to detect, locate, and characterizethe proppant-filled fracture 32.

According to certain embodiments of the electromagnetic method of thepresent invention and as shown schematically in FIG. 4, a power controlbox 40 is connected to casing 22 by a cable 42 so that electric currentis injected into the fracture well 20 by directly energizing the casing22 at the well head. In one embodiment, the power control box 40 isconnected wirelessly by a receiver/transmitter 43 to areceiver/transmitter 39 on equipment truck 41. Those of ordinary skillin the art will recognize that other suitable means of carrying thecurrent to the energizing point may also be employed.

As shown schematically in FIGS. 4-6, a plurality of electric andmagnetic field sensors 38 will be located on the earth's surface in arectangular or other suitable array covering the area around thefracture well 20 and above the anticipated fracture 32. In oneembodiment, the sensors 38 are connected wirelessly to areceiver/transmitter 39 on equipment truck 41. The maximum dimension ofthe array (aperture) in general should be at least 80 percent of thedepth to the fracture zone. The sensors 38 will measure the x, y and zcomponent responses of the electric and magnetic fields. It is theseresponses that will be used to infer location and characterization ofthe electrically conducting proppant through comparison to numericalsimulations and/or inversion of the measured data to determine thesource of the responses. The responses of the electric and magneticfield components will depend upon: the orientation of the fracture well20, the orientation of the fracture 32, the electrical conductivity,magnetic permeability, and electric permittivity of layers 24 a-24 j,the electrical conductivity, magnetic permeability, and electricpermittivity of the proppant filled fracture 32, and the volume of theproppant filled fracture 32. Moreover, the electrical conductivity,magnetic permeability and electric permittivity of the geological layersresiding between the surface and the target formation layers 24 a-24 jinfluence the recorded responses. From the field-recorded responses,details of the proppant filled fracture 32 can be determined.

In another embodiment, electric and magnetic sensors may be located inadjacent well/boreholes.

Depending upon the conductivity of the earth surrounding the well casing22, the current may or may not be uniform as the current flows back tothe surface along the well casing 22. According to both embodimentsshown in FIG. 4, current leakage occurs along wellbore 20 such as alongpath 50 or 52 and returns to the electrical ground 54 which isestablished at the well head. As described in U.S. patent applicationSer. No. 13/206,041 filed Aug. 9, 2011 and entitled “Simulating CurrentFlow Through a Well Casing and an Induced Fracture,” the entiredisclosure of which is incorporated herein by reference, the well casingis represented as a leaky transmission line in data analysis andnumerical modeling. Numerical simulations have shown that for aconducting earth (conductivity greater than approximately 0.05 siemensper meter (S/m)), the current will leak out into the formation, while ifthe conductivity is less than approximately 0.05 S/m the current will bemore-or-less uniform along the well casing 22. As shown in FIGS. 7A and7B, to localize the current in the well casing 22, electricallyinsulating pipe joints or pipe collars may be installed. According tothe embodiment shown in FIG. 7A, an insulating joint may be installed bycoating the mating surfaces 60 and 62 of the joint with a material 64having a high dielectric strength, such as any one of the well-known andcommercially available plastic or resin materials which have a highdielectric strength and which are of a tough and flexible characteradapted to adhere to the joint surfaces so as to remain in place betweenthe joint surfaces. As described in U.S. Pat. No. 2,940,787, the entiredisclosure of which is incorporated herein by reference, such plastic orresin materials include epoxies, phenolics, rubber compositions, andalkyds, and various combinations thereof. Additional materials includepolyetherimide and modified polyphenylene oxide. According to theembodiment shown in FIG. 7B, the mating ends 70 and 72 of the joint areengaged with an electrically insulated casing collar 74. Thetransmission line representation is able to handle various well casingscenarios, such as vertical only, slant wells, vertical and horizontalsections of casing, and, single or multiple insulating gaps.

The detection, location, and characterization of the electricallyconducting proppant in a fracture will depend upon several factors,including but not limited to the net electrical conductivity of thefracture, fracture volume, the electrical conductivity, magneticpermeability, and electric permittivity of the earth surrounding thefracture and between the fracture and surface mounted sensors. The netelectrical conductivity of the fracture means the combination of theelectrical conductivity of the fracture, the proppant and the fluidswhen all are placed in the earth minus the electrical conductivity ofthe earth formation when the fracture, proppant and fluids were notpresent. Also, the total electrical conductivity of the proppant filledfracture is the combination of the electrical conductivity created bymaking a fracture, plus the electrical conductivity of the new/modifiedproppant plus the electrical conductivity of the fluids, plus theelectro-kinetic effects of moving fluids through a porous body such as aproppant pack. The volume of an overly simplified fracture with thegeometric form of a plane may be determined by multiplying the height,length, and width (i.e. gap) of the fracture. A three dimensional (3D)finite-difference electromagnetic algorithm that solves Maxwell'sequations of electromagnetism may be used for numerical simulations. Inorder for the electromagnetic response of a proppant filled fracture atdepth to be detectable at the Earth's surface, the net fractureconductivity multiplied by the fracture volume within one computationalcell of the finite difference (FD) grid must be larger thanapproximately 100 Sm² for a Barnett shale-like model where the totalfracture volume is approximately 38 m³. For the Barnett shale model, thedepth of the fracture is 2000 m. These requirements for the numericalsimulations can be translated to properties in a field application forformations other than the Barnett shale.

The propagation and/or diffusion of electromagnetic (EM) wavefieldsthrough three-dimensional (3D) geological media are governed byMaxwell's equations of electromagnetism.

According to one embodiment of the present invention, the measured threedimensional components of the electric and magnetic field responses maybe analyzed with imaging methods such as an inversion algorithm based onMaxwell's equations and electromagnetic migration and/or holography todetermine proppant pack location. Inversion of acquired data todetermine proppant pack location involves adjusting the earth modelparameters, including but not limited to the proppant location within afracture or fractures and the net electrical conductivity of thefracture, to obtain the best fit to forward model calculations ofresponses for an assumed earth model. As described in Bartel, L. C.,Integral wave-migration method applied to electromagnetic data, SandiaNational Laboratories, 1994, the electromagnetic integral wave migrationmethod utilizes Gauss's theorem where the data obtained over an apertureis projected into the subsurface to form an image of the proppant pack.Also, as described in Bartel, L. C., Application of EM HolographicMethods to Borehole Vertical Electric Source Data to Map a Fuel OilSpill, Sandia National Laboratories, 1993, the electromagneticholographic method is based on the seismic holographic method and relieson constructive and destructive interferences where the data and thesource wave form are projected into an earth volume to form an image ofthe proppant pack. Due to the long wave lengths of the low frequencyelectromagnetic responses for the migration and holographic methods, itmay be necessary to transform the data into another domain where thewave lengths are shorter. As described in Lee, K. H., et al., A newapproach to modeling the electromagnetic response of conductive media,Geophysics, Vol. 54, No. 9 (1989), this domain is referred to as theq-domain. Further, as described in Lee, K. H., et al., TomographicImaging of Electrical Conductivity Using Low-Frequency ElectromagneticFields, Lawrence Berkeley Lab, 1992, the wave length changes when thetransformation is applied.

Also, combining Maxwell's equations of electromagnetism withconstitutive relations appropriate for time-independent isotropic mediayields a system of six coupled first-order partial differentialequations referred to as the “EH” system. The name derives from thedependent variables contained therein, namely the electric vector E andthe magnetic vector H. Coefficients in the EH system are the threematerial properties, namely electrical current conductivity, magneticpermeability, and electric permittivity. All of these parameters mayvary with 3D spatial position. The inhomogeneous terms in the EH systemrepresent various body sources of electromagnetic waves, and includeconduction current sources, magnetic induction sources, and displacementcurrent sources. Conduction current sources, representing current flowin wires, cables, and borehole casings, are the most commonly-usedsources in field electromagnetic data acquisition experiments.

An explicit, time-domain, finite-difference (FD) numerical method isused to solve the EH system for the three components of the electricvector E and the three components of the magnetic vector H, as functionsof position and time. A three-dimensional gridded representation of theelectromagnetic medium parameters, referred to as the “earth model” isrequired, and may be constructed from available geophysical logs andgeological information. A magnitude, direction, and waveform for thecurrent source are also input to the algorithm. The waveform may have apulse-like shape (as in a Gaussian pulse), or may be a repeating squarewave containing both positive and negative polarity portions, but is notlimited to these two particular options. Execution of the numericalalgorithm generates electromagnetic responses in the form of time seriesrecorded at receiver locations distributed on or within the griddedearth model. These responses represent the three components of the E orH vector, or their time-derivatives.

Repeated execution of the finite-difference numerical algorithm enablesa quantitative estimate of the magnitude and frequency-content ofelectromagnetic responses (measured on the earth's surface or in nearbyboreholes) to be made as important modeling parameters are varied. Forexample, the depth of current source may be changed from shallow todeep. The current source may be localized at a point, or may be aspatially-extended transmission line, as with an electrically chargedborehole casing. The source waveform may be broad-band or narrow-band inspectral content. Finally, changes to the electromagnetic earth modelcan be made, perhaps to assess the shielding effect of shallowconductive layers. The goal of such a modeling campaign is to assess thesensitivity of recorded electromagnetic data to variations in pertinentparameters. In turn, this information is used to design optimal fielddata acquisition geometries that have enhanced potential for imaging aproppant-filled fracture at depth.

The electric and magnetic responses are scalable with the input currentmagnitude. In order to obtain responses above the backgroundelectromagnetic noise, a large current on the order of 10 to 100 ampsmay be required. The impedance of the electric cable to the currentcontact point and the earth contact resistance will determine thevoltage that is required to obtain a desired current. The contactresistance is expected to be small and will not dominate the requiredvoltage. In addition, it may be necessary to sum many repetitions of themeasured data to obtain a measurable signal level over the noise level.In the field application and modeling scenarios, a time-domain currentsource waveform may be used. A typical time-domain waveform consists ofan on time of positive current followed by an off time followed by an ontime of negative current. In other words, + current, then off, then −current, then off again. The repetition rate to be used would bedetermined by how long the current has to be on until a steady-state isreached or alternatively how long the energizing current has to be offuntil the fields have died to nearly zero. In this exemplary method, themeasured responses would be analyzed using both the steady-state valuesand the decaying fields following the current shut-off. The advantage ofanalyzing the data when the energizing current is zero (decaying fields)is that the primary field contribution (response from the transmittingconductor; i.e., the well casing) has been eliminated and only the earthresponses are measured. In addition, the off period of the time domaininput signal allows analysis of the direct current electrical fieldsthat may arise from electro-kinetic effects, including but not limitedto, flowing fluids and proppant during the fracturing process. Fractureproperties (orientation, length, volume, height and asymmetry will bedetermined through inversion of the measured data and/or a form ofholographic reconstruction of that portion of the earth (fracture) thatyielded the measured electrical responses or secondary fields. Accordingto certain embodiments, a pre-fracture survey will be prepared toisolate the secondary fields due to the fracture. Those of ordinaryskill in the art will recognize that other techniques for analyzing therecorded electromagnetic data, such as use of a pulse-like currentsource waveform and full waveform inversion of observed electromagneticdata may also be used.

A field data acquisition experiment was conducted to test thetransmission line representation of a well casing current source. Thecalculated electric field and the measured electric field are in goodagreement. This test demonstrates that the transmission line currentsource implementation in the 3D finite-difference electromagnetic codegives accurate results. The agreement, of course, depends upon anaccurate model describing the electromagnetic properties of the earth.In this field data acquisition experiment, common electrical logs wereused to characterize the electrical properties of the earth surroundingthe test well bore and to construct the earth model.

The following examples are included to demonstrate illustrativeembodiments of the present invention. It will be appreciated by those ofordinary skill in the art that the techniques disclosed in theseexamples are merely illustrative and are not limiting. Indeed, those ofordinary skill in the art should, in light of the present disclosure,appreciate that many changes can be made in the specific embodimentsthat are disclosed, and still obtain a like or similar result withoutdeparting from the spirit and scope of the invention.

Example 1

Conventional low density and medium density ceramic proppants which arecommercially available from CARBO Ceramics, Inc. of Houston, Tex. underthe trade names CARBOLite (CL) 20/40, HydroProp 40/80, CARBOProp 20/40and CARBOProp 40170 were coated with thin layers of metals using RFmagnetron sputtering. Three metal targets were used for the depositions,namely aluminum, copper and nickel. The depositions were performed in asputter chamber using a 200 W RF power, a deposition pressure of 5mTorr, and an argon background (90 seem). The sputter chamber had threearticulating 2 inch target holders that can be used to coat complexshapes. The system also had a rotating water-cooled sample stage thatwas used in a sputter-down configuration. Prior to coating theproppants, deposition rates for the three metals were determined bysputtering the metals onto silicon wafers and measuring the coatingthickness by scanning electron microscope (SEM) cross-sectional analysiswith a Zeiss Neon 40 SEM.

The proppants were loaded into the sputter chamber in a 12 inch diameteraluminum pan with 1 inch tall sides. Approximately 130 g of proppant wasused for each coating run. This amount of proppant provided roughly asingle layer of proppant on the base of the pan. The proppant was“stirred” during the deposition using a 6 inch long fine wire metal thatwas suspended above the pan and placed into contact with the proppant inthe pan. The coating deposition times were doubled compared to what wasdetermined from the silicon wafer coating thickness measurements toaccount for roughly coating the proppants on one side, rolling themover, and then coating the other side. Coatings of approximately 100 nmand approximately 500 nm were deposited on each type of proppant witheach of the three metals.

Following the coating process, the proppant was inspected visually andby optical microscopy. The results indicated that the proppant having athinner coating of approximately 100 nm had a generally non-uniformcoating while the proppant with the thicker coating of approximately 500nm had a uniform coating.

Example 2

Conventional low density ceramic proppants which are commerciallyavailable from CARBO Ceramics, Inc. of Houston, Tex. under the tradenames of CARBOLite 20/40 and HydroProp 40/80 were coated with thinlayers of a conductive polymer using a planetary bench mixer with a “B”flat beater and a heating mantle. Approximately 500 g of proppant wasused for each coating run. Coatings of 0.1% by weight and 0.4% by weightof the proppant were prepared as shown in Table I below:

TABLE I Conductive polymer 0.1% coating 0.4% coating PEDOT:PSS 42 g 167g Obtained from Sigma-Aldrich as a 1.2% solution in water PANI 10 40 gObtained from Sigma-Aldrich in an emeraldine base, as a 5% solution intetrahydrofuran (THF) and doped with a 4-dodecylbenzene sulfonic acid ina 1:1 molar ratio PPY 10 g 40 g Obtained from Sigma-Aldrich as a doped5% dispersion in water

In each case, the proppant was heated to a temperature of 150-200° C. inan oven and was added to a steel mixing bowl. An adhesion promoter, suchas aminopropyl triethoxy silane, an amino-functional coupling agent, andglycidyloxypropyl trimethoxy silane, a functional organosilane couplingagent, was added to the heated proppant to enhance the bond between theinorganic substrate and the organic polymer. The mixing bowl was set inan external heating mantle to allow the heat to remain in the system asadditives were added. The “B” flat beater traveled along the side of thewall surfaces of the mixing bowl in circular orbits at an intermediatespeed of approximately 280 rpm while the mixing bowl stayed in place,thereby allowing complete mixing in a short time. A typical batchschedule is shown in Table II below:

TABLE II Coating Schedule on Ceramics: Ingredient Time of AdditionSubstrate 0 s Adhesion Promoter 7 s Conductive Polymer 15 s End Cycle5-10 min

Additionally, 0.1% and 0.4% coatings were made by adding PEDOT:PSS to aphenol-formaldehyde (Novolac) coating using a planetary mixer with “B”flat beater and a heating mantle as described above. Approximately 500 gof proppant was used for each coating run. For a 0.1% and 0.4% by weightcoating of the proppant, approximately 42 g and 167 g of PEDOT:PSS,respectively, were added to 500 g of proppant with 20 g ofphenol-formaldehyde (Novolac) resin cross-linked with hexamine (13%hexamine based on phenol-formaldehyde (Novolac) resin) with and withoutadhesion promoters as mentioned above. A typical batch schedule is shownin Table III below:

TABLE III Coating Schedule on Ceramics with Phenol-Formaldehyde Resin:Ingredient Time of Addition Substrate 0 s Phenol-Formaldehyde resin 0 sAdhesion Promoter 7 s Hexamine (cross-linker) 30 s Conductive Polymer1.5-2 min End Cycle 5-10 min

Following the coating process, the coated proppant samples wereinspected visually and by optical microscopy.

Example 3

The electrical conductivity of various proppant samples preparedaccording to Examples 1 and 2 as well as uncoated proppant samples weremeasured using the test device shown in FIG. 8. As shown in FIG. 8, thetest system 200 included an insulating boron nitride die 202, having aninside diameter of 0.5 inches and an outside diameter of 1.0 inches,disposed in a bore 204 in a steel die 206 in which the bore 204 had aninside diameter of 1.0 inches. Upper and lower steel plungers 208 and210 having an outside diameter of 0.5 inches were inserted in the upperand lower ends 212, 214, respectively, of the insulating boron nitridedie 202 such that a chamber 216 is formed between the leading end 218 ofthe upper plunger 208, the leading end 220 of the lower plunger 210 andthe inner wall 222 of the boron nitride sleeve 202. Upper plunger 208was removed from the insulating boron nitride die 202 and proppant wasloaded into the chamber 216 until the proppant bed 224 reached a heightof about 1 to 2 cm above the leading end 220 of the lower plunger 210.The upper plunger 208 was then reinstalled in the insulating boronnitride die 202 until the leading end 218 of the upper plunger 208engaged the proppant 224. A copper wire 226 was connected to the upperplunger 208 and one pole of each of a current source 228 and a voltmeter230. A second copper wire 232 was connected to the lower plunger 210 andthe other pole of each of the current source 228 and the voltmeter 230.The current source may be any suitable DC current source well known tothose of ordinary skill in the art such as a Keithley 237 High VoltageSource Measurement Unit in the DC current source mode and the voltmetermay be any suitable voltmeter well known to those of ordinary skill inthe art such as a Fluke 175 True RMS Multimeter which may be used in theDC mV mode for certain samples and in the ohmmeter mode for higherresistance samples.

The current source was powered on and the resistance of the test system200 with the proppant bed 224 in the chamber 216 was then determined.The resistance of the proppant 224 was then measured with the Multimeteras a function of pressure using the upper plunger 108 and lower plunger110 both as electrodes and to apply pressure to the proppant bed 224.Specifically, R=V/I−the resistance of the system with the plungerstouching is subtracted from the values measured with the proppant bed224 in the chamber 216 and the resistivity, p=R*Alt where A is the areaoccupied by the proppant bed 224 and t is the thickness of the proppantbed 224 between the upper plunger 108 and the lower plunger 110.

The results were as follows:

Electrical measurements of base proppants without the addition of anyconductive material were conducted at 100 V DC on samples that were 50volume % proppant in wax that were pressed into discs nominally 1 inchin diameter and approximately 2 mm thick. Using these values tocalculate the resistivity and using the measured resistivity for purewax, the values below were extrapolated by plotting log (resistivity)vs. volume fraction proppant and extrapolating to a volume fraction ofone:

CarboProp 40/70: 2×10¹² Ohm-cm

CarboProp 20/40: 0.6×10¹² Ohm-cm

CarboHydroProp: 1.8×10¹² Ohm-cm

CarboEconoProp: 9×10¹² Ohm-cm

It should be noted that the resistivities of the samples measured aboveare very high and not suitable for detection in the present invention.

Electrical measurements of base proppants with coatings of aluminum inthicknesses of 100 nm and 500 nm prepared according to Example 1, andbase proppants with coatings of 0.1% or 0.4% ofpoly(3,4-ethylenedioxythiophene) (PEDOT), with or without amino silanewere conducted. The results are shown in Table IV below and FIG. 9.

TABLE IV Resistivity (ohm-cm) Description 0 psi 1500 psi 2500 psi 3000psi 5000 psi Base Material-no 9 × 10¹² Not Not Not Not coating/nomodification measured measured measured measured CL w/0.1% PEDOT Notmeasured 1000 to 5000 1000 to 5000 1000 to 5000 1000 to 5000 CL w/0.1%Not measured 10,000 to 100,000 10,000 to 50,000 10,000 to 25,000 Notmeasured PEDOT/amino silane CL w/0.4% PEDOT Not measured 1000 to 50001000 to 5000 1000 to 5000 1000 to 5000 CL w/0.4% Not measured 5000 to10,000 ~5000 ~5000 Not PEDOT/amino silane measured CL w/100 nm Al coatNot measured 1,000 1,000 1,000 Not measured CL w/500 nm Al coat 5 to 10~0 0.1-0 0.1-0 0.1-0 CL w/500 nm Al coat Not measured ~0 0.27 Not Notmeasured measured HP w/100 nm Al coat Notmeasured >1,000,000 >1,000,000 >1,000,000 >1,000,000 HP w/500 nm Al coatNot measured 0-1 0.30 0-1 0-1

As can be seen from FIG. 9, the best results in terms of conductivitywere obtained with CarboLite (CL) 20/40 and HydroProp (HP) 40/80 havinga 500 nm thick coating of aluminum.

Electrical measurements of mixtures of base proppants with varyingpercentages of such base proppants with coatings of aluminum inthicknesses of 500 nm prepared according to Example 1 were conducted.The results are shown in Tables V and VI below and FIGS. 10-11.

Table V shows data for mixtures of CarboLite 20/40 with a 500 nm coatingof aluminum and CarboLite 20/40 with no added conductive material. Foreach sample shown in Table V, 3 g. of the sample material was placed inthe 0.5 inch die to provide an area of 0.196 square inches. The appliedcurrent for each test was 5 mA and the tests were conducted at roomtemperature.

TABLE V Load Pressure Voltage Resistance Resistivity (lbs) (psi) (mV)(Ohm) (Ohm-cm) 80% 500 nm Al-coated Carbolite with 20% Carbolite 20/40100 509 6.1 1.22 1.107 200 1019 5.6 1.12 1.016 300 1528 5.0 1.00 0.907400 2037 4.7 0.94 0.853 500 2546 4.5 0.90 0.817 60% 500 nm Al-coatedCarbolite with 40% Carbolite 20/40 200 1019 20.0 4.00 3.630 300 152817.8 3.56 3.230 400 2037 17.0 3.40 3.085 500 2546 16.1 3.22 2.922 6003056 15.8 3.16 2.867 40% 500 nm Al-coated Carbolite with 60% Carbolite20/40 100 509 253 50.60 46.516 200 119 223 44.60 41.000 300 1528 21843.60 40.080 400 2037 226 45.20 41.552 500 2546 221 44.20 40.632

Table VI shows data for mixtures of HydroProp 40/80 with a 500 nmcoating of aluminum and HydroProp 40/80 with no added conductivematerial. For each sample shown in Table VI, 3 g. of the sample materialwas placed in the 0.5 inch die to provide an area of 0.196 squareinches. The applied current for each test was 5 mA and the tests wereconducted at room temperature.

TABLE VI Load Pressure Voltage Resistance Resistivity (lbs) (psi) (mV)(Ohm) (Ohm-cm) 80% 500 nm Al-coated HydroProp 40/80 with 20% HydroProp40/80 100 509 5.9 1.18 1.083 200 1019 5.3 1.06 0.973 300 1528 4.9 0.980.900 400 2037 4.6 0.92 0.845 500 2546 4.4 0.88 0.808 60% 500 nmAl-coated HydroProp 40/80 with 40% HydroProp 200 1019 17.5 3.50 3.167300 1528 15.6 3.12 2.823 400 2037 14.5 2.90 2.624 500 2546 13.8 2.762.497 40% 500 nm Al-coated HydroProp 40/80 with 60% HydroProp 200 1019550 110.00 99.532 300 1528 470 94.00 85.055 400 2037 406 81.20 73.473500 2546 397 79.40 71.844

As can be seen from TABLES V and VI as well as FIGS. 10-11, theresistivity of the proppant packs, regardless of the relative amounts ofcoated or un-coated proppant, tends to decrease with increasing closurepressure. In addition, as the relative amount of uncoated proppantincreases and the relative amount of coated proppant decreases, theresistivity of the proppant packs increases dramatically. Lastly, thelowest resistivity is achieved with 100% Al-coated proppant. No mixtureof coated and uncoated proppant results in a resistivity measurementless than 100% Al-coated proppant.

When used as a proppant, the particles described herein may be handledin the same manner as conventional proppants. For example, the particlesmay be delivered to the well site in bags or in bulk form along with theother materials used in fracturing treatment. Conventional equipment andtechniques may be used to place the particles in the formation as aproppant. For example, the particles are mixed with a fracture fluid,which is then injected into a fracture in the formation.

In an exemplary method of fracturing a subterranean formation, ahydraulic fluid is injected into the formation at a rate and pressuresufficient to open a fracture therein, and a fluid containing sintered,substantially round and spherical particles prepared from a slurry asdescribed herein and having one or more of the properties as describedherein is injected into the fracture to prop the fracture in an opencondition.

The foregoing description and embodiments are intended to illustrate theinvention without limiting it thereby. It will be understood thatvarious modifications can be made in the invention without departingfrom the spirit or scope thereof

What is claimed is:
 1. A method of adjusting an earth model, comprising:performing one or more numerical simulations solving Maxwell's equationsof electromagnetism, wherein the numerical simulations are based upon anearth model containing parameters comprising proppant location within afracture and a net electrical conductivity of the fracture; obtainingmeasured electromagnetic field responses generated by: electricallyenergizing a fracture that is at least partially filled with proppantand an electrically-conductive material to generate electromagneticfield responses, and detecting the electromagnetic field responses witha plurality of sensors to provide the measured electromagnetic fieldresponses; and analyzing the measured electromagnetic field responseswith an inversion algorithm based on Maxwell's equations forelectromagnetism to determine a location of the proppant, whereinanalyzing the measured electromagnetic field responses includesadjusting the parameters of the model to fit the measuredelectromagnetic field responses, wherein the electromagnetic fieldresponses comprise secondary electric and magnetic fields.
 2. The methodof claim 1, wherein a substantially uniform coating of theelectrically-conductive material having a thickness of at least about500 nm is formed on an outer surface of a sintered, substantially roundand spherical particle.
 3. The method of claim 1, wherein theelectrically-conductive material comprises a metal selected from thegroup consisting of aluminum, copper and nickel.
 4. The method of claim1, wherein the electrically-conductive material comprises graphite,single or double-walled carbon nanotubes, or conducting nanoparticles orany combination or mixture thereof.
 5. The method of claim 1, whereinthe electrically-conductive material is coated with a water solublecoating for delayed release of the electrically-conductive material intothe fracture.
 6. The method of claim 1, wherein the detecting ofelectromagnetic field responses from the plurality of sensors comprisesmeasuring three dimensional (x, y, and z) components of electric fieldresponses.
 7. The method of claim 1, wherein the detecting ofelectromagnetic field responses from the plurality of sensors comprisesmeasuring three dimensional (x, y, and z) components of magnetic fieldresponses.
 8. The method of claim 1, wherein the plurality of sensorsare configured to measure three dimensional (x, y, and z) components ofelectric and magnetic field responses.
 9. A method of fracturing asubterranean formation, comprising: utilizing an image obtained from amethod of forming an image of a proppant pack, comprising: obtainingmeasured electric and magnetic field responses generated by:electrically energizing a subterranean fracture that is at leastpartially filled with the proppant pack to generate electric andmagnetic field responses, wherein the proppant pack comprises proppantand an electrically-conductive material, and detecting the electric andmagnetic field responses with a plurality of sensors to provide themeasured electric and magnetic field responses; and projecting theelectric and magnetic field responses and a source wave form into anearth volume to form the image of the proppant pack using constructiveand destructive interferences, to select an amount of a hydraulic fluidand proppant to inject into a wellbore extending into the subterraneanformation; injecting the hydraulic fluid and proppant into the wellboreat a rate and pressure sufficient to open a fracture therein; andplacing at least a portion of the proppant into the fracture.
 10. Themethod of claim 9, wherein a substantially uniform coating of theelectrically-conductive material having a thickness of at least about500 nm is formed on an outer surface of a sintered, substantially roundand spherical particle.
 11. The method of claim 9, wherein theelectrically-conductive material comprises a metal selected from thegroup consisting of aluminum, copper and nickel.
 12. The method of claim9, wherein the electrically-conductive material comprises graphite,single or double-walled carbon nanotubes, or conducting nanoparticles orany combination or mixture thereof.
 13. The method of claim 9, whereinthe electrically-conductive material is coated with a water solublecoating for delayed release of the electrically-conductive material intothe fracture.